Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming, and ultimately very expensive endeavors. As a result, over the years, a significant amount of added emphasis has been placed on overall well architecture, monitoring and follow on interventional maintenance. Indeed, perhaps even more emphasis has been directed at minimizing costs associated with applications in furtherance of well construction, monitoring and maintenance. All in all, careful attention to the cost effective and reliable execution of such applications may help maximize production and extend well life. Thus, a substantial return on the investment in the completed well may be better ensured.
In line with the objectives of maximizing cost effectiveness and overall production, the well may be of a fairly sophisticated architecture. For example, the well may be tens of thousands of feet deep, traversing various formation layers, and zonally isolated throughout. That is to say, packers may be intermittently disposed about production tubing which runs through the well so as to isolate various well regions or zones from one another. Thus, production may be extracted from certain zones through the production tubing, but not others. Similarly, production tubing that terminates adjacent a production region is generally anchored or immobilized in place thereat by a mechanical packer, irrespective of any zonal isolation.
A packer, such as the noted mechanical packer, may be secured near the terminal end of the production tubing and equipped with a setting mechanism. The setting mechanism may be configured to drive the packer from a lower profile to a radially enlarged profile. Thus, the tubing may be advanced within the well and into position with the packer in a reduced or lower profile. Subsequently, the packer may be enlarged to secure the tubing in place adjacent the production region.
Once the production tubing is in place, activation of the setting mechanism is generally hydraulically triggered. More specifically, the mechanism is equipped with a trigger that is responsive to a given degree of pressure induced in the well. So, for example, surface equipment and pumps adjacent the well head at surface may be employed to induce between about 3,000 and 4,000 PSI in the well. Depending on the location of the trigger for the setting mechanism, this driving up of pressure may take place through the bore of the production tubing or through the annulus between the tubing and the wall of the well.
Unfortunately, the noted hydraulic manner of driving up pressure for triggering of the setting mechanism may place significant stress on the production tubing. For example, where the hydraulic pressure is induced through the tubing bore, the strain on the tubing may lead to ballooning. Furthermore, the strain on the tubing may have long term effects. That is to say, even long after setting the packer, strain placed on the tubing during the hydraulic setting of the packer may result in failure, for example, during production operations. To avoid such a catastrophic event, whenever pressure tolerances are detectably exceeded, the entire production tubing string and packer assembly may be removed, examined, and another deployment of production equipment undertaken. Ultimately, this may eat up a couple of days' time and upwards of $100,000 in expenses.
In order to avoid the costly scenario of having to remove and re-deploy the entire production string, other manners of packer setting are available. For example, a dedicated hydraulic control line may be run to the setting mechanism from surface. Indeed, this may already be done where the production tubing is open to the well, rendering well hydraulics unavailable for triggering of the mechanism. Regardless, a dedicated hydraulic line to the setting mechanism means that exposure of the production tubing to dramatic pressure increases for packer deployment is eliminated. Thus, the possibility of tubing failure in the future due to prior hydraulic strain is reduced.
Unfortunately, the utilization of a dedicated hydraulic line for the setting mechanism only shifts the concerns over hydraulic deployment from potential production tubing issues to issues with other downhole production equipment. For example, a dedicated hydraulic line is itself an added piece of production equipment. Thus, it comes with its own added expenses and failure modes. Indeed, due to the fact that a new piece of equipment is introduced, the possibility of defective production string equipment is inherently increased even before a setting application is run. Once more, where such defectiveness results in a failure, the same amount of time and expenses may be lost in removal and re-deployment of the production string. Thus, the advantages obtained from protecting the production tubing by utilization of a dedicated hydraulic line for the setting mechanism may be negligible at best.